The Southeast European day-ahead electricity market tightened significantly on 8 July, although price movements varied across the region. The HUPX day-ahead price climbed to €128.17/MWh, an increase of €21.3/MWh from the previous day, while Romania, Croatia and Slovenia traded within a narrow range of €127–128/MWh, effectively aligning with the Hungarian market. Italy remained the region’s highest-priced market at €146.43/MWh, whereas Serbia recorded the lowest price at €104.08/MWh, leaving the SEEPEX market at a discount of more than €24/MWh compared with HUPX.
The price increase was driven by a combination of market fundamentals rather than higher temperatures alone. Although the regional average temperature declined by 2.3°C to 20.7°C, forecast electricity demand increased by 768 MW to 32,667 MW, reflecting a return to normal weekday consumption patterns. At the same time, forecast solar generation fell by 807 MW to 5,752 MW, while wind generation improved by 336 MW to 1,517 MW. The reduction in solar output increased reliance on imports and dispatchable generation, particularly during morning and evening hours, reinforcing tighter market conditions across much of Southeast Europe.
Market pricing continued to reflect a pronounced duck-curve pattern. On HUPX, the baseload price settled at €128.17/MWh, while the peak block averaged €102.2/MWh and the off-peak block reached €154.1/MWh. This unusual price structure illustrates how abundant solar generation suppresses daytime prices, while reduced renewable output outside solar hours increases the value of flexible resources such as battery storage, hydropower, gas-fired generation and cross-border electricity trading.
Cross-border flows further highlighted the region’s growing dependence on international electricity markets. Southeast Europe recorded net imports of 2,352 MW, with 3,537 MW imported from the Austria-Slovakia corridor, while simultaneously exporting 1,066 MW to Italy. The Italian market maintained a premium of €18.26/MWh over Hungary, continuing to attract electricity flows despite the region’s reliance on imports from Central Europe. This demonstrates the increasingly important role of transmission capacity and interconnector availability in regional price formation.
Hungary remained the central pricing hub within the region. The country imported 1,277 MW of electricity as domestic generation of 3,383 MW fell short of consumption of 4,660 MW. Supported primarily by Paks nuclear generation, solar production and imports, Hungary continued to influence regional pricing. Although the premium over the German market narrowed, HUPX still traded €29.21/MWh above Germany, preserving the commercial attractiveness of electricity flows from Central Europe.
Serbia stood out as the day’s principal market outlier. While most neighbouring markets experienced strong price increases, SEEPEX declined by €3.9/MWh to €104.08/MWh. Domestic consumption remained stable at 3,560 MW, while generation reached 3,136 MW, leaving Serbia a net importer of 425 MW. Coal-fired generation continued to dominate the supply mix with 2,578 MW, complemented by 693 MW of hydropower, while wind generation remained minimal at only 18 MW. Despite offering the lowest prices in the region, Serbia’s discount did not translate into significantly higher exports because cross-border transmission constraints and commercial flow patterns limited arbitrage opportunities.
Bulgaria maintained its position as the region’s strongest electricity exporter. The country exported 1,303 MW, supported by generation of 5,129 MW against domestic demand of 3,826 MW. Nuclear generation remained the backbone of the system at approximately 1,886 MW, while solar output also made a substantial contribution. As a result, IBEX closed at €117.80/MWh, remaining below Hungarian and Romanian prices despite a strong €14.8/MWh daily increase. Romania, meanwhile, traded almost identically to Hungary at €127.09/MWh while importing 589 MW, with nuclear, hydropower, gas and solar generation all contributing to the supply mix.
Croatia and Slovenia also traded close to Hungarian price levels due to continued import dependence. CROPEX reached €127.08/MWh, with Croatia importing 1,064 MW, while BSP Slovenia settled at €128.40/MWh as Slovenia imported 390 MW. Montenegro also recorded a notable increase, with prices rising to €117.54/MWh, up €23.7/MWh from the previous day. Although Montenegro remained a net importer by 132 MW, it continued to facilitate commercial electricity exports toward Italy through the undersea interconnector, reinforcing its strategic role as a regional transit market.
Forward markets presented a more balanced outlook than the spot market. The HU Week 29 contract declined to €130.50/MWh, down €1.5/MWh on the day and 9.38% over the previous week. In contrast, the HU Q4 Base contract increased to €145/MWh, while the HU Cal-27 contract stood at €114/MWh, indicating that market participants continue to assign a higher risk premium to the winter delivery period despite short-term price volatility. In fuel markets, CEGH natural gas strengthened to €47.39/MWh, while EU Emissions Allowances (EUA) eased to €80.19/t, leaving fuel and carbon costs supportive of wholesale electricity prices without generating additional upward pressure.
Overall, the trading session confirmed that Southeast Europe continues to operate as a collection of interconnected but distinct electricity markets rather than a single uniform region. Italy remained the premium destination for electricity exports, Hungary continued to act as the region’s principal pricing and import hub, Bulgaria strengthened its position as the leading exporter, while Serbia remained the lowest-priced market despite ongoing import dependence. Looking ahead, market direction is likely to depend less on average temperatures and more on hourly renewable generation, cross-border transmission availability, Central European import flows, and whether Serbia’s discounted pricing can translate into stronger regional electricity exports.